Method and apparatus for determining flow rates

ABSTRACT

A fibre optic sensor system provides sufficient thermal information to determine the mass flow rates of produced fluids within a well bore, using an optical fibre placed within or adjacent to the well bore without interference with production or prejudicing the integrity of the well. Mass flow rates of fluid in a conduit ( 20 ) located in a heat sink differing in temperature from the fluid are determined by obtaining a distributed temperature profile ( 32 ) of fluid flowing along a length of conduit ( 15 ) by using optical data obtained from a length of optical fibre in thermal contact therewith, obtaining a profile of the heat sink temperature external to the conduit, and deriving mass flow rates of fluids in the conduit from the said profiles and from measured thermal transfer parameters.

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application is a continuation of U.S. Ser. No. 10/030,506filed by Brown on Sep. 9, 2002, which is a continuation of InternationalApplication Number PCT/GB99/00129 filed on Jul. 6, 2000, which claimspriority from Great Britain Application Number 9916022.8 filed on Jul.9, 1999.

[0002] This invention relates to a method and apparatus for determiningflow rates. In particular, it is concerned with the determination of therate of flow of fluids in a conduit, using techniques for acquiring adistributed temperature profile in an optical fibre over a period oftime; using this time-dependent temperature data the mass flow rates offluids along the conduit can be determined when appropriate constantsare known. These constants relate to a number of parameters, of whichtime is of particular importance, and also include measures of distanceand thermal variables such as temperature, conductivity and specificheat.

[0003] Mass flow rate information is a very important tool for theefficient management of oil wells and the like. It is of courseimportant to have reliable production data, as soon as possible, notonly for its own sake. If flow rate data is promptly available, it mayalso be actively used to adjust or improve the flow rates, to diagnoseimmediate or potential problems, or to trigger alarms. Significantvariations in flow can be met with an appropriate management response.

[0004] It has been known in principle for over 25 years that thermaldata can be used to derive mass flow rate information, and that thisinformation is applicable to oil field operations and the like.Reference is made to the paper “Use of the Temperature Log forDetermining Flow Rates in Producing Wells”, Curtis M R and Witterholt EJ, Society of Petroleum Engineers of AIME Paper No SPE 4637. Curtis andWitterholt describe a method for calculating mass flow rate of a fluidup a well bore as a function of the temperature profile based onalgorithms developed by Ramey, published as “Well-bore HeatTransmission”, Ramey H, J.Pet.Tech., April 1962.

[0005] Nevertheless, as a practical matter, in the economically andcommercially important field of determining the mass flow rate ofproduced or injected fluids within a well bore, downhole measurementshave typically been made using either spinner or venturi techniques inone or a plurality of locations within the production tubing. Theequipment or devices that have been used have been either permanentlyinstalled in the well bore or conveyed into a measuring location bywireline.

[0006] These currently used devices do however have well knowndisadvantages. The spinner device is typically run on a wireline. Use ofthis technique commonly involves shutting in the well for extendedperiods while setting up the equipment, and then running the sensor andcable in the well, which presents a hazard to the integrity of the well.Surveys of this kind are carried out infrequently, and only provide aninstantaneous picture of the flow characteristics of the well.

[0007] In order to obtain continuous flow information, it is necessaryto use downhole instrumentation that is permanently installed. Aparticular benefit of permanent instrumentation is that it enables aproducing well to be better controlled. Venturi techniques, in which thepressure drop across a known orifice is measured, enable flow rates tobe permanently monitored, but do however have limitations. Firstly, theorifice device restricts the internal diameter of the tubing. Secondly,the device relies upon two independent high accuracy pressure sensors,but the output of such devices has a tendency to drift with time.Thirdly, the venturi device must be routinely calibrated to a fixedfluid mix density, to ensure continued accuracy of measurement.

[0008] For the foregoing reasons, among others, there is and has beenfor a long time a continuing need to find and develop improved methodsfor downhole mass flow rate monitoring.

[0009] We have developed sensing and measuring equipment based onopto-electronic systems at a surface location operatively connected tofibre optic sensors deployed downhole. Using such systems, it is notnecessary to have any electronics downhole and the fibre sensors canprovide temperature and pressure information, while being resistant totemperatures up to 250□ C. and above.

[0010] It has been known for over 15 years that optical fibres canreport temperature distributions. See for example GB 2122337 and EP0213872. We have now found that it is possible to combine, in a usefuland practical and advantageous manner, the derivation of mass flow ratesfrom thermal data with the acquisition of thermal data by means of afibre optic sensor.

[0011] Typically, the thermal data is acquired as follows. A laser lightpulse is sent down an optical fibre wave guide. As the pulse of lighttravels along the wave guide, the thermal molecular vibration at eachpoint along the length of the wave guide causes a very weak reflectedsignal to travel back up the fibre towards the source. An opticalcoupler splits the reflected light away from the fibre and takes it to adetector. The time lapse between the launch of the light pulse anddetection allows the distance of the reflection point down the opticalfibre to be calculated, since the speed of light in the fibre isconstant and is known. The amplitude of the returned light is a functionof the molecular vibration at the reflection point, increasing withincreasing temperature. As reflected light is detected over a timeperiod corresponding for the time taken for the light pulse to travelthe length of the optical fibre and back, the output of the detector iseffectively a distributed temperature profile along the whole length ofthe fibre.

[0012] The present invention addresses the deficiencies of the prior artmethods of determining downhole flow rates and provides methods andapparatus utilising a distributed fibre optic sensor. We have found thata single optical sensor system can provide sufficient thermalinformation to determine the mass flow rates of produced fluids within awell bore, using an optical fibre placed within or adjacent to the wellbore, almost instantaneously, at any time, substantially continuously ifrequired, without interference with production or prejudicing theintegrity of the well.

[0013] The present invention concerns aspects of the method andapparatus described below. The scope of the invention extends to allnovel aspects thereof whether individually or in combination with any ofthe other features disclosed herein.

[0014] More specifically, in one aspect of the invention a method ofdetermining mass flow rates of fluid in a conduit located in a heat sinkdiffering in temperature from the fluid may comprise obtaining adistributed temperature profile of fluid flowing along a length ofconduit by means of optical data obtained from a length of optical fibrein thermal contact therewith, obtaining a profile of the heat sinktemperature external to the conduit, and deriving mass flow rates offluids in the conduit from the said profiles and from measured thermaltransfer parameters.

[0015] Correspondingly, apparatus for determining mass flow rates offluid in a conduit located in a heat sink differing in temperature fromthe fluid may comprise a length of optical fibre in thermal contact withthe fluid, means for obtaining a distributed temperature profile offluid flowing along a length of conduit by means of optical dataobtained from said length of optical fibre, and means for deriving massflow rates of fluids in the conduit from the said distributedtemperature profile, from a profile of the heat sink temperatureexternal to the conduit, and from measured thermal transfer parameters.

[0016] In a further aspect of the invention there is provided a methodof monitoring the mass flow rates of fluids flowing in variablequantities along a length of underground conduit, including monitoringthe said rates during both a calibration period and an observationperiod (which may include some or all of the calibration period); whichmethod comprises:

[0017] (a) establishing distributed temperature measuring apparatuscomprising an optical fibre extending along the said length of conduitin thermal contact with the fluid and/or with the conduit, together withmeans for passing light along the optical fibre in the said length,receiving light emergent therefrom and interpreting temperature- andlocation-related characteristics of said emergent light in terms of thetemperature profile of the optical fibre at a series of locations alongthe said length of conduit;

[0018] (b) determining the natural geothermal profile along the lengthof the conduit to be monitored (the natural profile being the profile inthe absence of heating or cooling from the conduit);

[0019] (c) running fluid to be monitored through the said length ofconduit; (d) in the calibration period:

[0020] (i) measuring the actual mass flow rates of the fluid during timeintervals;

[0021] (ii) during those intervals, obtaining distributed temperatureprofiles of the length of conduit by passing light along the opticalfibre and interpreting temperature- and location-related characteristicsof light emergent from the said length;

[0022] (iii) correlating the distributed temperature profiles observedin (i) with the flow rates measured in (ii) whereby to obtaincalibration data which calibrate the temperature measuring apparatus interms of mass flow rate;

[0023] (e) in the observation period: monitoring the distributedtemperature profile of the length of conduit by means of the distributedtemperature measuring apparatus and obtaining therefrom the flow ratesof the fluid in the length of conduit using the calibration dataobtained in the calibration period.

[0024] Correspondingly, apparatus for monitoring the mass flow rates offluids flowing in variable quantities along a length of undergroundconduit may comprise:

[0025] (a) distributed temperature measuring apparatus comprising anoptical fibre extending along the said length of conduit in thermalcontact with the fluid and/or with the conduit, together with means forpassing light along the optical fibre in the said length, receivinglight emergent therefrom and interpreting temperature- andlocation-related characteristics of said emergent light in terms of thetemperature profile of the optical fibre at a series of locations alongthe said length of conduit;

[0026] (b) means for determininig the natural geothermal profile alongthe length of the conduit to be monitored (the natural profile being theprofile in the absence of heating or cooling from the conduit);

[0027] (c) optionally, means for measuring the actual mass flow rates ofthe fluid during time intervals in a calibration period;

[0028] (d) means for correlating distributed temperature profilesobtained from (a) with actual flow rates whereby to obtain calibrationdata which calibrate the temperature measuring apparatus in terms ofmass flow rate;

[0029] (e) means for monitoring the distributed temperature profile ofthe length of conduit by means of the distributed temperature measuringapparatus and obtaining therefrom the flow rates of the fluid in thelength of conduit using the calibration data obtained from (d).

[0030] Various preferred and optional features of the invention willbecome apparent from the following description.

[0031] In an embodiment of the invention, a fibre optic distributedtemperature sensor is installed in a well bore inside a thermallyconductive tube which is suitably clamped or bonded to a substantialcontinuous fixed structure extending over the length of well bore inwhich the optical fibre is operatively deployed. Suitably, the fixedstructure may be the conduit for the fluid whose mass flow rate is to bemeasured. This conduit may be the oil well casing, or the productiontubing, or any other similar conduit appropriate to the particulardownhole environment where the flow rate is required to be known.

[0032] The tube may be filled with thermally conductive liquid, toensure functional thermal contact between the optical fibre and theconduit concerned, and preferably between the fibre and the fluid whoseflow rate is to be determined.

[0033] The mass flow rate of the fluid is determined by the applicationof predetermined algorithms to the distributed temperature profile thatis determined for the fluid. Typical applications of the invention arethe calculation of mass flow rate in producing oil, water and gas wells,in a variety of different fluid combinations, and in injecting waterwells.

[0034] Among the different possible methods of determining mass flowrate from temperature, two are preferred in the practice of the presentinvention.

[0035] In a first preferred method, flow rate data is derived from thethermal behaviour of fluids flowing through massive undergroundformations, which act as heat sinks at their natural temperatures, thatis to say their temperatures in the absence of any flow of heating orcooling fluid through the conduit that runs through these formations.Generally speaking, in a vertical well, the temperature rises more orless linearly with depth, and it is normally sufficiently accurate forthe purposes of the present invention to treat the resulting geothermalgradient as being linear. As fluid flows along the conduit it is heatedor cooled by conduction. The temperature at any point depends on thethermal properties of the flowing fluid, of the installed completion(the production tubing and associated hardware within the lined wellbore of a well, including such equipment as down-hole safety valves,packers and circulating valves) and of the surrounding formation, and isdependent upon flow rate, pressure, volume, temperature (PVT),Joule-Thompson effects, and frictional losses, and can be timedependent.

[0036] It is observed that, starting from a point of interest deepwithin the well, which may be a point at which fluid in temperatureequilibrium with the surrounding formation is introduced into the wellbore, the temperature profile of the fluid above that point (as thefluid flows upwards through a heat sink of progressively lowertemperature) takes the form of a curve which approaches an asymptote toa straight line parallel to the geothermal profile, ie of the samegeothermal gradient but displaced by a certain temperature. The actualshape of the asymptotic curve is determined by the thermal properties ofthe system, mass flow rates, friction, Joule-Thompson and PVT propertiesof the flowing fluid as has been described in publications such asCurtis and Witterholt, SPE 4637, mentioned above, to which referenceshould be made for further details.

[0037] Appropriate algorithms for this first preferred method are:

T(z,t)=T _(ge) +G _(g) z−G _(g) A+(T _(fe) −T _(ge) +G _(g) A)e ^(−z/A)

[0038] where

[0039] A=Q□_(f)C_(f)(k_(h)+r_(ci)Uf(t))/2□r_(ci)Uk_(h)

[0040] and

f(t)=−−ln(r _(ce)/2(□t)^(0.5)−0.29

[0041] G_(g)=Geothermal gradient

[0042] T_(ge)=Geothermal temperature at depth of fluid entry

[0043] T_(fe)=Fluid entry temperature

[0044] Z=distance from entry zone

[0045] Q=Mass flow rate

[0046] □_(f)=Fluid density

[0047] C_(f)=Fluid specific heat

[0048] k_(h)=formal thermal conductivity

[0049] U=Overall heat transfer coefficient

[0050] t=Flowing time

[0051] r_(ci)=Inner radius of casing

[0052] r_(ce)=Outer radius of casing

[0053] □=Thermal diffusivity of casing

[0054] Equivalent algorithms exist for calculating the flow rate offluid being injected into an underground reservoir. See for example thepaper “Temperature Logging in Injection Wells”, Witterholt E J andTixier M P, SPE 4022. Similarly, for gas production, see for example thepaper “Temperature Surveys in Gas Producing Wells”, by Tixier M P andKunz K S, AIME Annual Meeting, Chicago 1955. These algorithms may beimproved by taking into account the effective heating due to flowingfriction pressure drop. Additionally, changes in pressure, volume andtemperature properties up the well may be taken into account by the useof computer nodal analysis. Suitable commercially available temperaturemodelling software includes that sold by Landmark under the trade nameWellCat.

[0055] During the calibration period, the algorithms are used while theactual fluid flow rate is determined independently, so that the flowrate becomes a known value. The known flow rate, whether a flow rate offluid produced from the well or a flow rate of fluid injected into thewell, is compared with the measured temperature profile of the length ofconduit in consideration, as a function of producing time and depth. Thecomparison may be optimised by modification of the formula constantssuch as fluid specific heat (C_(f)), the thermal conductivity of thesurrounding rock formation (k_(h)), the overall heat transfercoefficient (U) and the thermal diffusivity of the casing (□), which arespecific to a particular well completion, a particular formation, andparticular fluid properties. In effect, the calibration phase in whichthe actual flow rates are known enables the constants in the algorithmsto be established for a particular well. A more accurate analysis may beobtained by calculating the formula constants themselves, by employing aleast squares regression fit of the predicted data to the measured dataas a function of time and depth and flow rate.

[0056] Once the constants in the algorithms have been derived as afunction of known flow rates during the calibration period, it ispossible to calculate the flow rate in an observation period using thesame derived constants. Normally, the observation period will follow thecalibration period, and this is of course essential if real time data isrequired. It would however be possible to use an observation periodbefore a calibration period, if it would be acceptable to derive onlyhistoric data.

[0057] A second preferred method for deriving mass flow rates fromtemperature data occurs where the temperature of the flowing fluidchanges as a result of a change, typically a loss, of pressure. This maybe due to a discontinuous change in the size or type of conduit, forexample a 3½″ to 4½″ (89 mm to 114 mm) crossover, or at a tubing shoe orthe like, or a loss of pressure along a horizontal length of productionconduit. The temperature changes can be related, by the use ofappropriate equations, to the flow rate of the fluid. Again, parametersthat are fixed as constants in a particular downhole environment are thethermal properties of the flowing fluid, of the installed completion andof the surrounding formation. Dynamic properties of the fluid such asits Joule-Thompson and PVT characteristics should also be taken intoaccount.

[0058] When this approach is followed, the temperature profile at achange in flowing cross section of the conduit is characterised byeither an increase or a decrease in temperature. The mass flow rate ofthe fluid can be determined, as before, from an analysis of the timebased distributed temperature profile over the length of conduitconcerned, where the PVT characteristics of the flowing fluid are knownand the other relevant constants are derived from measurements madeduring the calibration period when the flow rates are known.

[0059] The algorithms defining the relationship between the temperatureprofile, the length of the conduit being investigated, and time, withrespect to the thermal properties of the flowing fluid and thesurroundings, are available from published literature describing heattransfer in pipelines. Reference is made in particular to two books:

[0060] 1 Hein, Michael A. “HP 41 Pipeline Hydraulics and Heat TransferPrograms”, Pennwell books, 1984, ISDN 0878 14 255X

[0061] 2 Carslaw, H. S. and Jaeger, J. C. “Conduction of Heat inSolids”, Clarendon Press, 2^(nd) Edition, 1959.

[0062] The invention is illustrated diagrammatically by way of examplein the accompanying drawing, FIG. 1, which illustrates on the left handside a cross section of a producing oil well, and on the right hand sidea graph of temperature (abscissa) against height/depth (ordinate), thedepth scale being indicated by the corresponding location in theadjacent depicted well bore.

[0063] In FIG. 1, the oil well is shown with a casing 11 extending fromthe ground surface 12 into and through a producing reservoir 13.Production tubing 15 extends inside the casing from the usual oil flowcontrol apparatus 16 located above ground at the wellhead and terminatesinside the casing at a depth D above a producing zone 17. The upperboundary of the producing zone is marked by a closure 18 which holds thelower end of the production tubing in place within the casing.

[0064] In accordance with the invention, an optical fibre is deployedwithin the well in a suitable duct, such as optical fibre deploymenttube 20, which is a continuous tube having two limbs, in effect aU-tube, beginning and ending in connection with surface mountedinstrumentation 22, including a light source, a detector and dataprocessing apparatus, as means for passing light along the opticalfibre, receiving light emergent therefrom and interpreting temperature-and location-related characteristics of said emergent light in terms ofthe temperature profile of the optical fibre at a series of locationsalong the fibre sensor deployed in the well. The deployment tube extendsfrom the instrumentation down the well between the production tubing andthe casing, through closure 18 and through the producing zone 17,returning by the same route. The tube is thermally conductive, and willtypically be clamped to the outside of the production tubing, in goodthermal contact therewith, but may alternatively be installed on the oilwell casing, if fluid temperatures in the annulus between tubing andcasing are to be measured.

[0065] The instrumentation 22 may comprise commercially availableinstrumentation, such as the model DTS-800 made by York Sensors Ltd ofChandlers Ford, Hampshire. The optical fibre within tube 20 is desirablycoated to withstand the high temperatures and corrosive fluidsencountered in a downhole environment. Typically, the fibre willcomprise an inner core or wave guide of about 50 μm diameter surroundedby a lower refractive index cladding, total diameter about 125 μm. Thecladding may be coated with a sealing layer that is impervious todownhole fluids, and finally an abrasion resistant coating to bring thetotal diameter of the fibre up to about 155-400 μm.

[0066] Such a fibre can be deployed in the deployment tube 20 byhydraulic means, and can correspondingly be replaced if necessary. Thedeployment fluid provides a thermal bridge to the tube wall, so that theoptical fibre is in thermal contact with the fluids whose mass flowrates are to be measured, in the conduit comprised of the productiontubing and the well casing. With appropriate instrumentation,temperatures can be measured from −40□ C. to +300□ C., with an accuracyof 0.5□ or better. The temperature measurements are absolute rather thanrelative, do not drift and do not need calibration against anyreference. In practical terms, the information can be obtainedcontinuously, meaning as frequently as every 7 seconds at intervals of 1m along the fibre, for a fibre length of up to 10 km. In a 40 km fibre,temperature readings at 10 m intervals are effectively continuous overthe length of the fibre.

[0067] The graphical right hand side of FIG. 1 illustrates the measuredtemperature profiles. The natural geothermal profile 30 is a straightline relation between depth and temperature. It is derived from simpletemperature measurements, by conventional apparatus, at differentdepths. Deviations from a straight line, due to varying thermalconductivities in the surrounding formation, are considered to be sominor as to be insignificant for the purposes of the invention, inalmost all cases.

[0068] The heavier curve 32 represents the distributed temperatureprofile over the whole well. It coincides with the geothermal profilebelow the reservoir 13, where there is no flow, and the fluid is atequilibrium with its surroundings. As fluid enters the well from thereservoir and rises in the producing zone 17, it passes into coolerregions and begins to lose heat to the surrounding formations, which actas a heat sink at a temperature related to depth by the geothermalprofile. Depending on flow rates, conductivities and the like, thetemperature of the fluid rising in the well falls. At depth D, thediameter of the conduit, constituted by the casing 11 in the producingzone 17 and by the tubing 15 above depth D, is suddenly reduced. Asillustrated, the fluid temperature drops sharply at point 36 as itenters the narrower bore of the production tubing. Thereafter, therising fluid continues to show a temperature differential to thesurrounding formation, and the relation between its temperature and itsdepth approaches the asymptote 34 which is a straight line at thegeothermal gradient, displaced from the geothermal profile 30 by thedifference in temperature between the temperature of fluid rising in asteady state from an indefinitely deep well and the temperature of thesurrounding rock.

[0069] The distributed temperature profile curve 32 provides the basisfor the derivation of the required mass flow rates, as described. It iscalibrated by measurements made at a time when mass flow rates aredetermined independently by conventional means, such as by spinner orventuri methods. Data processing in the instrumentation 22 provides realtime information which is invaluable in managing the oil well. The novelapplication of thermal analytical techniques to temperature data derivedfrom optical fibre distributed temperature sensors, in accordance withthis invention, enables accurate, substantially non-intrusive, andeasily replaceable downhole apparatus to give continuous real-time massflow data. This in turn can be used in many ways, as well known in theart, to enhance oil well management.

What is claimed is:
 1. A method for determining a flow parameter of afluid stream within a conduit that extends into a well bore, comprising:deploying an optical fiber to measure a temperature at a location alongthe conduit, the temperature being representative of the fluidtemperature at the location; and deriving a flow rate for the fluidbased on the temperature at the location.
 2. The method as recited inclaim 1, wherein the flow rate is a mass flow rate.
 3. The method asrecited in claim 1, wherein deploying comprises measuring a temperatureprofile along at least part of the conduit and deriving comprisesderiving a flow rate for the fluid based on the temperature profile. 4.The method as recited in claim 3, wherein deriving comprises derivingthe flow rate for the fluid based on the temperature profile relative toa natural geothermal profile.
 5. The method as recited in claim 3,further comprising measuring the temperature profile at a plurality oftimes and deriving the flow rate for the fluid based on the temperatureprofile measured at the plurality of times.
 6. The method as recited inclaim 5, wherein deriving comprises calculating at least one constantfrom the temperature profile measured at the plurality of times.
 7. Themethod as recited in claim 1, wherein deploying comprises establishing adistributed temperature measuring apparatus.
 8. The method as recited inclaim 1, wherein deploying comprises deploying the optical fiber in thefluid.
 9. The method as recited in claim 1, wherein deploying comprisesdeploying the optical fiber along an exterior of the conduit.
 10. Themethod as recited in claim 1, wherein deploying comprises passing lightalong the optical fiber and receiving light reflected from the opticalfiber, the reflected light being indicative of the fluid temperature.11. The method as recited in claim 1, further comprising installing theoptical fiber in a thermally conductive tube.
 12. The method as recitedin claim 11, further comprising forming the thermally conductive tube ina U-shape extending along the conduit.
 13. The method as recited inclaim 3, further comprising determining the presence of a change in thecross-sectional area of the conduit by analyzing the temperatureprofile.
 14. A system for determining a mass flow rate of a fluid,comprising: a conduit extending through a surrounding heat sink; anoptical distributed temperature sensing device disposed along theconduit; and an instrumentation device coupled to the distributedtemperature sensing device to determine a temperature profile of thefluid for derivation of the mass flow rate of the fluid.
 15. The systemas recited in claim 14, wherein the conduit comprises production tubingfor the production of oil.
 16. The system as recited in claim 14,wherein the conduit comprises a casing lining a well bore.
 17. Thesystem as recited in claim 14, wherein the distributed temperaturesensing device comprises an optical fiber.
 18. The system as recited inclaim 17, wherein the optical fiber extends from the instrumentationdevice in a generally U-shaped loop.
 19. The system as recited in claim14, wherein the instrumentation comprises a laser.
 20. The system asrecited in claim 14, wherein the distributed temperature sensing deviceis configured to sense temperature at a plurality of locations along theconduit.
 21. A method for determining a parameter related to fluid flow,comprising: providing a fluid flow path through a heat sink; determininga natural thermal profile along the heat sink; measuring temperature ata plurality of locations along the fluid flow path with a distributedtemperature sensing system; and deriving a mass flow rate of a fluidflowing along the fluid flow path based on the natural thermal profileof the heat sink and the temperature measurements at the plurality oflocations.
 22. The method as recited in claim 21, wherein providingcomprises locating a conduit in an underground formation.
 23. The methodas recited in claim 21, wherein providing comprises locating a conduitin a well bore.
 24. The method as recited in claim 23, wherein measuringcomprises deploying an optical fiber along the conduit to sensetemperature at a plurality of locations along the conduit.
 25. Themethod as recited in claim 24, wherein deploying comprises placing theoptical fiber in a thermally conductive tube.
 26. The method as recitedin claim 21, wherein measuring comprises sensing a temperature profilealong a length of the fluid flow path.
 27. The method as recited inclaim 21, wherein measuring comprises sensing the temperature at aplurality of times and wherein deriving comprises deriving the mass flowrate based on the temperature measures at the plurality of times.
 28. Amethod for determining a parameter related to fluid flow in anunderground formation, comprising: obtaining distributed temperatureprofiles with an optical fiber deployed along a fluid flow path throughthe underground formation; and using the distributed temperatureprofiles to determine mass flow rates of fluid flowing along the fluidflow path.
 29. The method as recited in claim 28, further comprisingmeasuring a natural thermal profile along the underground formation. 30.The method as recited in claim 28, further comprising monitoring themass flow rates of fluid along the fluid flow path.
 31. The method asrecited in claim 28, further comprising calibrating temperaturemeasurement via the optical fiber.
 32. The method as recited in claim28, further comprising utilizing a conduit to form the fluid flow path.33. The method as recited in claim 32, further comprising producing oilthrough the conduit.
 34. The method as recited in claim 32, furthercomprising producing gas through the conduit.
 35. The method as recitedin claim 32, further comprising producing water through the conduit. 36.The method as recited in claim 28, wherein using comprises calculatingat least one constant from the distributed temperature profiles.